Myriad wells have been drilled into earth strata for the extraction of oil, gas, and other material there from. Typically, hydrocarbon wells are constructed by setting a string of pipe, commonly referred to as casing, in the wellbore and filling the space (annulus) between the wellbore and outer surface of the casing with cement. Completing a well in this manner allows for the flow of fluid from the surrounding formation to the well to be limited to selected zones. In order to permit fluid flow between the formation and well, the operator of the well will identify the particular strata where fluid will be injected and/or from which the hydrocarbons will be collected, and then will perforate the casing and cement at the appropriate location. The perforations may be created by bullets or jet shots discharged from a conventional perforating gun at high pressure and can extend through the walls of the casing and the cemented area such that the selected strata, referred to as the production zone, is in fluid communication with the interior portion of the casing in the well. Alternatively, holes may be cut through the pipe and cement by hydro-jetting. Some well constructions do not place cement in the annular space and are referred to as un-cemented completions. Sections of the un-cemented annulus may be segregated with external casing packers. Perforations or sliding sleeve assemblies are used to communicate the selected strata with the interior portion of the casing in the well. In the case of sliding sleeve assemblies, the sleeves are shifted open exposing a port to gain access to the formation.
After completing the well, the production zone of the formation may be treated to increase the flow of hydrocarbons into the well. Typically, a well may be fractured in the event the formation in the production zone is characterized by low permeability. The well may be fractured by a conventional manner, one such example being hydraulic fracturing. To hydraulically fracture a well, a fluid such as water containing a particulate material such as sand is pumped down under high pressure from the surface into the casing and out through the perforations, jetted holes or ports into the production zone to break the formation creating fractures. The particulate material lodges in the fractures and serves to “prop” the fractures open, thus increasing the permeability of the production zone and further increasing fluid flow into the well when the well is put on production.
One conventional manner of improving the results of the fracturing procedure is to ensure that the treating fluid is injected into the production zone with a fairly even flow distribution in all directions. However, achieving an even distribution can be difficult, because the formations in the production zone may not be of equal stress. The treating fluid will preferentially flow to the areas of least resistance, i.e., the areas of lowest stress, and high stress areas will receive correspondingly reduced flow rates. This problem can become especially acute when the production zone is long or there are a large number of perforations.
One method used to address this flow imbalance problem is the redirection of the treating fluid toward higher stress zones by using ball sealers to temporarily block perforations that exist across lower stress zones. These ball sealers are typically spherical in shape and have a diameter that is larger than the average perforation size, and are pumped into the casing along with the treating fluid. The flow pattern of the fluid preferentially carries the ball sealers toward the casing perforations that have the highest flow rate of fluid passing into the production zone. The ball sealers seat upon the perforations receiving the majority of fluid flow and, once seated, are held there by the pressure differential across the perforations. If a substantial number of the high flow perforations are blocked by ball sealers seated against them, then fluid flow can be diverted to the perforations which had relatively low flow rates, which can fracture the formation, thus increasing the flow capacity of the production zone. A more even flow distribution may be achieved and, as a result, the increase in hydrocarbon recovery can be larger than it would be if the flow imbalance was not corrected.
As mentioned above, the ball sealers may be pumped into the casing and transported by the treating fluid. Typically, no additional treatment equipment is required other than a ball injector and, optionally, a ball catcher. Advantages of utilizing ball sealers to divert flow of the treating fluid include ease of use, positive shutoff, no involvement with the formation, and low risk of incurring damage to the well. Generally, ball sealers are designed to be chemically inert in the environment to which they are exposed; to effectively seal, yet not extrude into the perforations. The ball sealers can be released from the perforations when the pressure differential into the formation is relieved, fluid flow is commenced into the casing, or alternatively can be physically removed from the perforation by contact with a weighted bar or gauge ring run on a pipe string or wireline. Some ball sealers are designed to dissolve with time and temperature. Such ball sealers are termed “biodegradable ball sealers.”
As the hydrocarbons flow into the well, the production zone depletes over time and it can be desirable to tap deposits that are trapped within the formation, either in existing production zones or new production zones. This can include fracturing the existing formation again, or optionally adding additional perforations and selectively treating the new perforations. However, treating a new production zone can be difficult without isolating the new untapped production zone from the existing production zone. Alternatively, there may be so many perforations and/or an exceedingly long perforated interval that the whole interval cannot be effectively contacted with a re-fracturing treatment. As will be appreciated by those skilled in the art, there are multiple conventional techniques available by which to isolate or seal the perforations associated with the existing production zone and thereby block communication with the wellbore.
One convention procedure utilizes pumping cement to seal the existing perforations, drilling out the cement from the casing, perforating and re-fracturing the well. However, the conventional procedures utilizing pumping cement to seal the existing perforations can be disadvantageous. The cement not only seals the casing but also can fill the fractures within the formation and can damage the near wellbore formation. Utilization of a workover rig to pump the cement and, optionally, drilling the cement out can be time consuming and expensive, thus undesirably reducing the efficiency by which the hydrocarbons can be obtained.
Another conventional procedure for sealing the perforations associated with the existing production zone and thereby blocking communication with the wellbore includes running a liner into the wellbore. This procedure involves hanging several hundred to several thousand feet of pipe (liner) inside the existing wellbore to cover the production zone and setting the liner in place. Optionally, an expandable liner may be inserted in the wellbore, wherein the liner expands to the inner diameter of the casing. However, the solution of adding a liner suffers from the problem of high cost for many feet of extra steel and has the additional complexity of hanging the liner in the hole, especially in lateral boreholes commonly found in horizontally developed shale plays. Additionally, the liner job also decreases the inside diameter of the wellbore, which can hinder future ability to work on the well.
As discussed above, conventional ball sealers may be injected into the wellbore to seal off perforations in the production zone. However, such ball sealers only temporarily seal off the perforations and typically the sealing relationship with the perforations is lost when the pressure differential across the perforations is lost due to the elimination of the treating fluid flow and/or the release of pressure. Furthermore, the effectiveness of the conventional ball sealers is limited by the flow rate of the treating fluid pumped into the wellbore. For example, in a typical lateral borehole, the flow rate of the treating fluid may be a maximum of one hundred barrels per minute. Such a flow rate may only result in a quarter to a little more than a third of the production zone sealed off in a lateral borehole as those typically drilled in horizontal shale plays.
In view of the above, it would be desirable to employ an inexpensive and time-efficient method to substantially seal off a production zone of a hydrocarbon well. It would further be desirable to substantially seal off a production zone utilizing a minimal amount of hardware and machinery, such that transport cost and time to the well site would be minimized. It would also be desirable to employ a method to substantially seal off a production zone utilizing fewer trained operators than traditionally needed in other conventional procedures. In addition, it would be desirable to employ a method to substantially seal off a production zone that does not damage and/or contaminate the surrounding formation. Furthermore, it would be desirable to employ a method of substantially and permanently sealing off a production zone in a horizontal wellbore in a horizontal shale play without damaging and/or contaminating the surrounding formation.